ML050190130
| ML050190130 | |
| Person / Time | |
|---|---|
| Site: | Catawba  |
| Issue date: | 01/13/2005 |
| From: | Sean Peters NRC/NRR/DLPM/LPD2 |
| To: | Jamil D Duke Energy Corp |
| Peters S, NRR/DLPM, 415-1842 | |
| Shared Package | |
| OARC20060713mjr=Changed the availability, Added the release date and SUNSI comment, Copied to DPC folder | List: |
| References | |
| TAC MB7842, TAC MB7843 | |
| Download: ML050190130 (33) | |
Text
TABLE OF CONTENTS (continued) 3.4 REACTOR COOLANT SYSTEM (RCS)........................... 3.4.1-1 3.4.1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits....
3.4.1-1 3.4.2 RCS Minimum Temperature for Criticality....
3.4.2-1 3.4.3 RCS Pressure and Temperature (PIT) Limits....
3.4.3-1 3.4.4 RCS Loops-MODES 1 and 2....
3.4.4-1 3.4.5 RCS Loops-MODE 3....
3.4.5-1 3.4.6 RCS Loops-MODE 4....
3.4.6-1 3.4.7 RCS Loops -MODE 5, Loops Filled....
3.4.7-1 3.4.8 RCS Loops-MODE 5, Loops Not Filled....
3.4.8-1 3.4.9 Pressurizer.................
3.4.9-1 3.4.10 Pressurizer Safety Valves.
3.4.10-1 3.4.11 Pressurizer Power Operated Relief Valves (PORVs)....
3.4.11-1 3.4.12 Low Temperature Overpressure Protection (LTOP) System....
3.4.12-1 3.4.13 RCS Operational LEAKAGE....
3.4.13-1 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage....
3.4.14-1 3.4.15 RCS Leakage Detection Instrumentation....
3.4.15-1 3.4.16 RCS Specific Activity..
3.4.16-1 3.4.17 RCS Loops-Test Exceptions....
3.4.17-1 3.4.18 Steam Generator (SG) Tube Integrity....
3.4.18-1 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)....
3.5.1-1 3.5.1 Accumulators....
3.5.1-1 3.5.2 ECCS-Operating....
3.5.2-1 3.5.3 ECCS-Shutdown....
3.5.3-1 3.5.4 Refueling Water Storage Tank (RWST)....
3.5.4-1 3.5.5 Seal Injection Flow....
3.5.5-1 3.6 CONTAINMENT SYSTEMS....
3.6.1-1 3.6.1 Containment....
3.6.1-1 3.6.2 Containment Air Locks........................
3.6.2-1 3.6.3 Containment Isolation Valves.3.6.3-1 3.6.4 Containment Pressure.3.6.4-1 3.6.5 Containment Air Temperature.3.6.5-1 3.6.6 Containment Spray System.3.6.6-1 3.6.7 Hydrogen Recombiners.3.6.7-1 3.6.8 Hydrogen Skimmer System (HSS).3.6.8-1 3.6.9 Hydrogen Ignition System (HIS).3.6.9-1 3.6.10 Annulus Ventilation System (AVS).3.6.10-1 3.6.11 Air Return System (ARS).
3.6.11-1 3.6.12 Ice Bed.3.6.12-1 3.6.13 Ice Condenser Doors.3.6.13-1 3.6.14 Divider Barrier Integrity.3.6.14-1 3.6.15 Containment Recirculation Drains.3.6.15-1 3.6.16 Reactor Building.3.6.16-1 3.6.17 Containment Valve Injection Water System (CVIWS)....
3.6.17-1 Catawba Units 1 and 2 ii Amendment Nos. 218 and 212
RCS Operational LEAKAGE 3.4.13 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.13 RCS Operational LEAKAGE LCO 3.4.13 RCS operational LEAKAGE shall be limited to:
- a.
- b.
1 gpm unidentified LEAKAGE;
- c.
10 gpm identified LEAKAGE; and
- d.
150 gallons per day primary to secondary LEAKAGE through any one steam generator (SG).
I APPLICABILITY:
MODES 1, 2, 3, and 4.
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.
RCS operational A.1 Reduce LEAKAGE to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> LEAKAGE not within within limits.
limits for reasons other than pressure boundary LEAKAGE or primary to secondary LEAKAGE.
B.
Required Action and B.1 Be in MODE 3.
6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition A not AND met.
B.2 Be in MODE 5.
36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> OR Pressure boundary LEAKAGE exists.
OR Primary to secondary LEAKAGE not within limit.
I I
Catawba Units 1 and 2 3;4;1 3-1 Amendment Nos. 218 and 212
RCS Operational LEAKAGE 3.4.13 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.13.1 NOTES
-NOTE-
- 1. Not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after Only required to establishment of steady state operation.
be performed during steady
- 2. Not applicable to primary to secondary LEAKAGE.
state operation Verify RCS Operational LEAKAGE within limits by 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> performance of RCS water inventory balance.
SR 3.4.13.2 ----------
NOTE---------NOTE-Not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after Only required to establishment of steady state operation.
be performed during steady state operation Verify primary to secondary LEAKAGE is < 150 gallons 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> per day through any one SG.
Catawba Units 1 and 2
-*3.4.13-2 Amendment Nos. 218 and 212
SG Tube Integrity 3.4.18 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.18 Steam Generator (SG) Tube Integrity LCO 3.4.18 SG tube integrity shall be maintained.
AND All SG tubes satisfying the tube repair criteria shall be plugged in accordance with the Steam Generator Program.
APPLICABILITY:
MODES 1, 2, 3, and 4.
ACTIONS NOT Separate Condition entry is allowed for each SG 1 I-t--
CONDITION REQUIRED ACTION COMPLETION TIME A. One or more SG tubes A.1 Verify tube integrity of 7 days satisfying the tube the affected tube(s) is repair criteria and not maintained until the next plugged in accordance inspection.
with the Steam Generator Program.
AND A.2 Plug the affected tube(s)
Prior to entering in accordance with the MODE 4 following Steam Generator the next refueling Program.
outage or SG tube inspection (continued)
Catawba Units 1 and 2 3.4.18-1 Amendment Nos. 218 and 212
SG Tube Integrity 3.4.18 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME B. Required Action and B.1 Be in MODE 3.
6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition A AND not met.
B.2 Be in MODE 5.
36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> OR SG tube integrity not maintained.
SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.18.1 Verify SG tube integrity in accordance with the In accordance Steam Generator Program.
with the Steam Generator Program SR 3.4.18.2 Verify that each inspected SG tube that Prior to entering satisfies the tube repair criteria is plugged in MODE 4 accordance with the Steam Generator following a SG Program.
tube inspection Catawba Units 1 and 2 3.4.18-2 Amendment Nos. 218 and 212
Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.8 Inservice Testing Program This program provides controls for inservice testing of ASME Code Class 1, 2, and 3 components including applicable supports. The program shall include the following:
- a.
Testing frequencies specified in Section Xl of the ASME Boiler and Pressure Vessel Code and applicable Addenda as follows:
ASME Boiler and Pressure Vessel Code and applicable Addenda terminology for inservice testing activities Required Frequencies for performing inservice testing activities Weekly Monthly Quarterly or every 3 months Semiannually or every 6 months Every 9 months Yearly or annually Biennially or every 2 years At least once per 7 days At least once per 31 days At least once per 92 days At least once per 184 days At least once per 276 days At least once per 366 days At least once per 731 days 5.5.9
- b.
The provisions of SR 3.0.2 are applicable to the above required Frequencies for performing inservice testing activities;
- c.
The provisions of SR 3.0.3 are applicable to inservice testing activities; and
- d.
Nothing in the ASME Boiler and Pressure Vessel Code shall be construed to supersede the requirements of any TS.
Steam Generator (SG) Program A Steam Generator Program shall be established and implemented to ensure that SG tube integrity is maintained. In addition, the Steam Generator Program shall include the following provisions:
- a.
Provisions for condition monitoring assessments. Condition monitoring assessment means an evaluation of the "as found" condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The "as found" condition refers to the (continued)
Catawba Units I and 2 5.5-6 Amendment rlos. 218 and 212
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued) condition of the tubing during a SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging of tubes. Condition monitoring assessments shall be conducted during each outage during which the SG tubes are inspected or plugged to confirm that the performance criteria are being met.
- b.
Performance criteria for SG tube integrity. SG tube integrity shall be maintained by meeting the performance criteria for tube structural integrity, accident induced leakage, and operational LEAKAGE.
- 1.
Structural integrity performance criterion: All inservice SG tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, and cooldown, and all anticipated transients included in the design specification) and design basis accidents.
This includes retaining a safety factor of 3.0 against burst under normal steady state full power operation primary to secondary pressure differential and a safety factor of 1.4 against burst applied to the design basis accident primary to secondary pressure differentials. Apart from the above requirements, additional loading conditions associated with the design basis accidents, or combination of accidents in accordance with the design and licensing basis, shall also be evaluated to determine if the associated loads contribute significantly to burst or collapse.
In the assessment of tube integrity, those loads that do significantly affect burst or collapse shall be determined and assessed in combination with the loads due to pressure with a safety factor of 1.2 on the combined primary loads and 1.0 on axial secondary loads.
- 2.
Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG.
Leakage is not to exceed 150 gallons per day through each SG for a total of 600 gallons per day through all SGs.
- 3.
The operational LEAKAGE performance criterion is specified in LCO 3.4.13, "RCS Operational LEAKAGE."
- c.
Provisions for SG tube repair criteria. Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged.
(continued)
Catawba Units 1 and 2 5.5-7 Amendment Nos. 218 and 212
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued)
- d.
Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. The number and portions of the tubes inspected and method of inspection shall be performed with the objective of detecting flaws of any type (for example, volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tube repair criteria. The tube-to-tubesheet weld is not part of the tube. In addition to meeting requirements d.1, d.2, d.3, and d.4 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. An assessment of degradation shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.
- 1.
Inspect 100% of the tubes in each SG during the first refueling outage following SG replacement.
- 2.
For Unit 1, inspect 100% of the tubes at sequential periods of 144, 108, 72, and, thereafter, 60 Effective Full Power Months (EFPM). The first sequential period shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for more than 72 EFPM or three refueling outages (whichever is less) without being inspected.
- 3.
For Unit 2, inspect 100% of the tubes at sequential periods of 120, 90, and, thereafter, 60 EFPM. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50%
by the refueling outage nearest the end of the period. No SG shall operate for more than 48 EFPM or two refueling outages (whichever is less) without being inspected.
- 4.
If crack indications are found in any SG tube, then the next inspection for each SG for the degradation mechanism that caused the crack indication shall not exceed 24 EFPM or one refueling outage (whichever is less). If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with crack(s), then the indication need (continued)
Catawba Units 1 and 2 5.5-8 Amendment Nos. 218 and 212
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued) not be treated as a crack.
- e.
Provisions for monitoring operational primary to secondary LEAKAGE.
5.5.10 Secondary Water Chemistry Program This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation and low pressure turbine disc stress corrosion cracking. The program shall include:
- a.
Identification of a sampling schedule for the critical variables and control points for these variables;
- b.
Identification of the procedures used to measure the values of the critical variables;
- c.
Identification of process sampling points, which shall include monitoring the discharge of the condensate pumps for evidence of condenser in leakage;
- d.
Procedures for the recording and management of data;
- e.
Procedures defining corrective actions for all off control point chemistry conditions; and
- f.
A procedure identifying the authority responsible for the interpretation of the data and the sequence and timing of administrative events, which is required to initiate corrective action.
5.5.11 Ventilation Filter Testing Program (VFTP)
A program shall be established to implement the following required testing of Engineered Safety Feature (ESF) filter ventilation systems in accordance with Regulatory Guide 1.52, Revision 2, and ANSI N510-1980, with exceptions as noted in the UFSAR.
- a.
Demonstrate for each of the ESF systems that an inplace test of the high efficiency particulate air (HEPA) filters shows the following penetration and system bypass when tested in accordance with Regulatory Guide 1.52, Revision 2, and ANSI N510-1980 at the flowrate specified below +/- 10%.
(continued)
Catawba Units 1 and 2 5.5-9 Amendment Nos. 218 and 212
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testing Program (VFTP) (continued)
ESF Ventilation System Penetration Flowrate Annulus Ventilation (Unit 1)
Annulus Ventilation (Unit 2)
Control Room Area Ventilation Aux. Bldg. Filtered Exhaust (Unit 1)
Aux. Bldg. Filtered Exhaust (Unit 2)
Containment Purge (non-ESF) (2 fans)
Fuel Bldg. Ventilation (Unit 1)
Fuel Bldg. Ventilation (Unit 2)
<1%
< 0.05%
< 0.05%
<1%
< 0.05%
<1%
<1%
< 0.05%
9000 cfm 9000 cfm 6000 cfm 30,000 cfm 30,000 cfm 25,000 din 16,565 cfm 16,565 cfm
- b.
Demonstrate for each of the ESF systems that an inplace test of the charcoal adsorber shows the following penetration and system bypass when tested in accordance with Regulatory Guide 1.52, Revision 2, and ANSI N510-1980 at the flowrate specified below +/- 10%.
ESF Ventilation System Penetration Flowrate Annulus Ventilation (Unit 1)
Annulus Ventilation (Unit 2)
Control Room Area Ventilation Aux. Bldg. Filtered Exhaust (Unit 1)
Aux. Bldg. Filtered Exhaust (Unit 2)
Containment Purge (non-ESF) (2 fans)
Fuel Bldg. Ventilation (Unit 1)
Fuel Bldg. Ventilation (Unit 2)
<1%
< 0.05%
< 0.05%
<1%
< 0.05%
<1%
<1%
< 0.05%
9000 cfm 9000 cfm 6000 cfm 30,000 cfm 30,000 cfm 25,000 cfm 16,565 cfm 16,565 cfm
- c.
Demonstrate for each of the ESF systems that a laboratory test of a sample of the charcoal adsorber, when obtained as described in Regulatory Guide 1.52, Revision 2, shows the methyl iodide penetration less than the value specified below when tested in accordance with ASTM D3803-1989 at a temperature of s 300C and greater than or equal to the relative humidity specified below.
ESF Ventilation System Annulus Ventilation Control Room Area Ventilation Aux. Bldg. Filtered Exhaust Containment Purge (non-ESF)
Fuel Bldg. Ventilation Penetration
<4%
< 0.95%
<4%
< 6%
<4%
RH 95%
95%
95%
95%
95%
(continued)
Catawba Units 1 and 2 5.5-10 Amendment Nos. 218 and 212
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testing Program (VFTP) (continued)
- d.
Demonstrate for each of the ESF systems that the pressure drop across the combined HEPA filters, the prefilters, and the charcoal adsorbers is less than the value specified below when tested in accordance with Regulatory Guide 1.52, Revision 2, and ANSI N510-1980 at the flowrate specified below +/- 10%.
ESF Ventilation System Delta P Flowrate Annulus Ventilation Control Room Area Ventilation Aux. Bldg. Filtered Exhaust Containment Purge (non-ESF) (2 fans)
Fuel Bldg. Ventilation 8.0 in wg 8.0 in wg 8.0 in wg 8.0 inwg 8.0 in wg 9000 cfm 6000 cfm 30,000 cfm 25,000 cfm 16,565 cfm
- e.
Demonstrate that the heaters for each of the ESF systems dissipate the value specified below when tested in accordance with ANSI N510-1980.
ESF Ventilation System Annulus Ventilation Control Room Area Ventilation Aux. Bldg. Filtered Exhaust Containment Purge (non-ESF)
Fuel Bldg. Ventilation Wattage @ 600 vac 45 + 6.7 kW 25+2.5kW 40 + 4.0 kW 120+ 12.0kW 80 + 8/-17.3 kW 5.5.12 The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the VFTP test frequencies.
Explosive Gas and Storage Tank Radioactivity Monitoring Program This program provides controls for potentially explosive gas mixtures contained in the Waste Gas Holdup System, the quantity of radioactivity contained in gas storage tanks or fed into the offgas treatment system, and the quantity of radioactivity contained in unprotected outdoor liquid storage tanks. The gaseous radioactivity quantities shall be determined following the methodology in Branch Technical Position (BTP) ETSB 11-5, "Postulated Radioactive Release due to Waste Gas System Leak or Failure". The liquid radwaste quantities shall be determined in accordance with Standard Review Plan, Section 15.7.3, "Postulated Radioactive Release due to Tank Failures".
(continued)
Catawba Units I and 2 5.5-11 Amendment.Nos.
218 and 212
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.12 Explosive Gas and Storage Tank Radioactivity Monitoring Program (continued)
The program shall include:
- a.
The limits for concentrations of hydrogen and oxygen in the Waste Gas Holdup System and a surveillance program to ensure the limits are maintained. Such limits shall be appropriate to the system's design criteria (i.e., whether or not the system is designed to withstand a hydrogen explosion);
- b.
A surveillance program to ensure that the quantity of radioactivity contained in each gas storage tank or connected gas storage tanks and fed into the offgas treatment system is less than the amount that would result in a Deep Dose Equivalent of > 0.5 rem to any individual in an unrestricted area, in the event of an uncontrolled release of the tanks' contents; and
- c.
A surveillance program to ensure that the quantity of radioactivity contained in all outdoor liquid radwaste tanks that are not surrounded by liners, dikes, or walls, capable of holding the tanks' contents and that do not have tank overflows and surrounding area drains connected to the Liquid Radwaste Treatment System is less than the amount that would result in concentrations exceeding the limits of 10 CFR 20, Appendix B, Table 2, Column 2, at the nearest potable water supply and the nearest surface water supply in an unrestricted area, in the event of an uncontrolled release of the tanks' contents.
The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Explosive Gas and Storage Tank Radioactivity Monitoring Program surveillance frequencies.
5.5.13 Diesel Fuel Oil Testinq Program A diesel fuel oil testing program to implement required testing of both new fuel oil and stored fuel oil shall be established. The program shall include sampling and testing requirements, and acceptance criteria, all in accordance with applicable ASTM Standards. The purpose of the program is to establish the following:
- a.
Acceptability of new fuel oil for use prior to addition to storage tanks by determining that the fuel oil has:
- 1.
an API gravity or an absolute specific gravity within limits,
- 2.
a flash point and kinematic viscosity within limits for ASTM 2D fuel oil, and (continued)
Catawba Units I and 2 5.5-12 Amendment Nos. 218 and 212
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.13 Diesel Fuel Oil Testing Program (continued)
- 3.
a clear and bright appearance with proper color or a water and sediment content within limits;
- b.
Other properties for ASTM 2D fuel oil are within limits within 31 days following sampling and addition to storage tanks; and
- c.
Total particulate concentration of the fuel oil is < 10 mg/l when tested every 31 days.
The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Diesel Fuel Oil Testing Program test frequencies.
5.5.14 Technical Specifications (TS) Bases Control Program This program provides a means for processing changes to the Bases of these Technical Specifications.
- a.
Changes to the Bases of the TS shall be made under appropriate administrative controls and reviews.
- b.
Licensees may make changes to Bases without prior NRC approval provided the changes do not require either of the following:
- 1.
a change in the TS incorporated in the license; or
- 2.
a change to the updated FSAR or Bases that requires NRC approval pursuant to 10 CFR 50.59.
- c.
The Bases Control Program shall contain provisions to ensure that the Bases are maintained consistent with the UFSAR.
- d.
Proposed changes that meet the criteria of Specification 5.5.14.b.1 or 5.5.14.b.2 above shall be reviewed and approved by the NRC prior to implementation. Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71(e), with approved exemptions.
(continued)
Catawba Units 1 and 2 5.5-1 3 Amendment Nos. 218 and 212
Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.15 Safety Function Determination Program (SFDP)
This program ensures loss of safety function is detected and appropriate actions taken. Upon entry into LCO 3.0.6, an evaluation shall be made to determine if loss of safety function exists. Additionally, other appropriate actions may be taken as a result of the support system inoperability and corresponding exception to entering supported system Condition and Required Actions. This program implements the requirements of LCO 3.0.6. The SFDP shall contain the following:
- a.
Provisions for cross train checks to ensure a loss of the capability to perform the safety function assumed in the accident analysis does not go undetected;
- b.
Provisions for ensuring the plant is maintained in a safe condition if a loss of function condition exists;
- c.
Provisions to ensure that an inoperable supported system's Completion Time is not inappropriately extended as a result of multiple support system inoperabilities; and
- d.
Other appropriate limitations and remedial or compensatory actions.
A loss of safety function exists when, assuming no concurrent single failure, a safety function assumed in the accident analysis cannot be performed. For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and:
- a.
A required system redundant to the system(s) supported by the inoperable support system is also inoperable; or
- b.
A required system redundant to the system(s) in turn supported by the inoperable supported system is also inoperable; or
- c.
A required system redundant to the support system(s) for the supported systems (a) and (b) above is also inoperable.
The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered.
Catawba Units I and 2 5.5-14 Amendment Nos. 218 and 212
Reporting Requirements 5.6 5.6 Reporting Requirements (continued) 5.6.7 PAM Report When a report is required by LCO 3.3.3, "Post Accident Monitoring (PAM)
Instrumentation," a report shall be submitted within the following 14 days. The report shall outline the preplanned alternate method of monitoring, the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status.
5.6.8 Steam Generator (SG) Tube Inspection Report A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of the inspection. The report shall include:
- a.
The scope of inspections performed on each SG,
- b.
Active degradation mechanisms found,
- c.
Non-destructive examination techniques utilized for each degradation mechanism,
- d.
Location, orientation (if linear), and measured sizes (if available) of service induced indications,
- e.
Number of tubes plugged during the inspection outage for each active degradation mechanism,
- f.
Total number and percentage of tubes plugged to date, and
- g.
The results of condition monitoring, including the results of tube pulls and in-situ testing.
Catawba Units 1 and 2 5.6-6 Amendment Nos. 218 and 212
TABLE OF CONTENTS B 3.4 REACTOR COOLANT SYSTEM (RCS) (continued)
B 3.4.9 Pressurizer..........................................
B 3.4.9-1 B 3.4.10 Pressurizer Safety Valves..........................................
B 3.4.10-1 B 3.4.11 Pressurizer Power Operated Relief Valves (PORVs)....................... B 3.4.11-1 B 3.4.12 Low Temperature Overpressure Protection (LTOP) System............ B 3.4.12-1 B 3.4.13 RCS Operational LEAKAGE..........................................
B 3.4.13-1 B 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage.................................. B 3.4.14-1 B 3.4.15 RCS Leakage Detection Instrumentation......................................... B 3.4.15-1 B 3.4.16 RCS Specific Activity..........................................
B 3.4.16-1 B 3.4.17 RCS Loops-Test Exceptions..........................................
B 3.4.17-1 B 3.4.18 Steam Generator (SG) Tube Integrity..........................................
B 3.4.18-1 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)
B 3.5.1 Accumulators.B 3.5.1-1 B 3.5.2 ECCS-Operating.B 3.5.2-1 B 3.5.3 ECCS-Shutdown.B 3.5.3-1 B 3.5.4 Refueling Water Storage Tank (RWST)
.B 3.5.4-1 B 3.5.5 Seal Injection Flow.B 3.5.5-1 B 3.6 CONTAINMENT SYSTEMS B 3.6.1 Containment........................
B 3.6.1-1 B 3.6.2 Containment Air Locks........................
B 3.6.2-1 B 3.6.3 Containment Isolation Valves........................
B 3.6.3-1 B 3.6.4 Containment Pressure........................
B 3.6.4-1 B 3.6.5 Containment Air Temperature........................
B 3.6.5-1 B 3.6.6 Containment Spray System........................
B 3.6.6-1 B 3.6.7 Hydrogen Recombiners........................
B 3.6.7-1 B 3.6.8 Hydrogen Skimmer System (HSS)........................
B 3.6.8-1 B 3.6.9 Hydrogen Ignition System (HIS)........................
B 3.6.9-1 B 3.6.10 Annulus Ventilation System (AVS)........................
B 3.6.10-1 B 3.6.11 Air Return System (ARS)........................
B 3.6.11-1 B 3.6.12 Ice Bed........................
B 3.6.12-1 B 3.6.13 Ice Condenser Doors.......................
B 3.6.13-1 B 3.6.14 Divider Barrier Integrity.......................
B 3.6.14-1 B 3.6.15 Containment Recirculation Drains.......................
B 3.6.15-1 B 3.6.16 Reactor Building.......................
B 3.6.16-1 B 3.6.17 Containment Valve Injection Water System (CVIWS)...................... B 3.6.17-1 B 3.7 PLANT SYSTEMS B 3.7.1 Main Steam Safety Valves (MSSVs)..........................
B 3.7.1-1 B 3.7.2 Main Steam Isolation Valves (MSIVs)..........................
B 3.7.2-1 B 3.7.3 Main Feedwater Isolation Valves (MFIVs), Main Feedwater Control Valves (MFCVs), their Associated Bypass Valves, and the Tempering Valves.............................................
B 3.7.3-1 B 3.7.4 Steam Generator Power Operated Relief Valves (SG PORVs)....... B 3.7.4-1 B 3.7.5 Auxiliary Feedwater (AFW) System............................................. B 3.7.5-1 B 3.7.6 Condensate Storage System (CSS).............................................
B 3.7.6-1 Catawba Units I and 2 ii Revision No. I
RCS Loops - MODES 1 and 2 B 3.4.4 BASES APPLICABLE SAFETY ANALYSES (continued) assuming the number of RCS loops in operation is consistent with the Technical Specifications. The majority of the plant safety analyses are based on initial conditions at high core power or zero power. The primary.
coolant flowrate, and thus the number of RCPs in operation, is an important assumption in all accident analyses (Ref. 1).
Steady state DNB analysis has been performed for the four RCS loop operation. For four RCS loop operation, the steady state DNB analysis, which generates the pressure and temperature Safety Limit (SL) (i.e., the departure from nucleate boiling ratio (DNBR) limit) assumes a maximum power level of 118% RTP. This is the design overpower condition for four RCS loop operation. The DNBR limit defines a locus of pressure and temperature points that result in a minimum DNBR greater than or equal to the critical heat flux correlation limit.
The plant is designed to operate with all RCS loops in operation to maintain DNBR above the SL, during all normal operations and anticipated transients. By ensuring heat transfer in the nucleate boiling region, adequate heat transfer is provided between the fuel cladding and the reactor coolant.
RCS Loops-MODES 1 and 2 satisfy Criterion 2 of 10 CFR 50.36 (Ref. 2).
LCO The purpose of this LCO is to require an adequate forced flow rate for core heat removal. Flow is represented by the number of RCPs in operation for removal of heat by the SGs. To meet safety analysis acceptance criteria for DNB, four pumps are required in MODES I and 2.
An OPERABLE RCS loop consists of an OPERABLE RCP in operation providing forced flow for heat transport and an OPERABLE SG.
APPLICABILITY In MODES 1 and 2, the reactor is critical and thus has the potential to produce maximum THERMAL POWER. Thus, to ensure that the assumptions of the accident analyses remain valid, all RCS loops are required to be OPERABLE and in operation in these MODES to prevent DNB and core damage.
The decay heat production rate is much lower than the full power heat rate. As such, the forced circulation flow and heat sink requirements are reduced for lower, noncritical MODES as indicated by the LCOs for MODES 3,4, and 5.
Operation in other MODES is covered by:
I Catawba Units I and 2 B 3.4.4-2 Revision No. 1
RCS Loops - MODE 3 B 3.4.5 BASES LCO (continued)
Utilization of the Note is permitted provided the following conditions are met, along with any other conditions imposed by initial startup test procedures:
- a.
No operations are permitted that would dilute the RCS boron concentration with coolant at boron concentration less than required to assure the SDM of LCO 3.1.1 and maintain keff < 0.99, thereby maintaining an adequate margin to criticality. Boron reduction with coolant at boron concentration less than required to assure SDM and maintain keff < 0.99, is prohibited because a uniform concentration distribution throughout the RCS cannot be ensured when in natural circulation; and
- b.
Core outlet temperature is maintained at least 1 0F below saturation temperature, so that no vapor bubble may form and possibly cause a natural circulation flow obstruction.
An OPERABLE RCS loop consists of one OPERABLE RCP and one OPERABLE SG, which has the minimum water level specified in SR 3.4.5.2. An RCP is OPERABLE if it is capable of being powered and is able to provide forced flow if required.
APPLICABILITY In MODE 3, this LCO ensures forced circulation of the reactor coolant to remove decay heat from the core and to provide proper boron mixing.
The most stringent condition of the LCO, that is, three RCS loops OPERABLE and three RCS loops in operation, applies to MODE 3 with RTBs in the closed position. The least stringent condition, that is, three RCS loops OPERABLE and one RCS loop in operation, applies to MODE 3 with the RTBs open.
Operation in other MODES is covered by:
LCO 3.4.4, "RCS Loops-MODES 1 and 2";
LCO 3.4.6, "RCS Loops-MODE 4";
LCO 3.4.7, "RCS Loops-MODE 5, Loops Filled";
LCO 3.4.8, "RCS Loops-MODE 5, Loops Not Filled";
LCO 3.4.17, "RCS Loops-Test Exceptions";
LCO 3.9.4, "Residual Heat Removal (RHR) and Coolant Circulation-High Water Level" (MODE 6); and LCO 3.9.5, "Residual Heat Removal (RHR) and Coolant Circulation-Low Water Level" (MODE 6).
Catawba Units 1 and 2 B 3.4.5-3 Revision No. 2
RCS Loops - MODE 4 B 3.4.6 BASES LCO (continued) performed during the startup testing program is the validation of rod drop times during cold conditions, both with and without flow. The no flow test may be performed in MODE 3, 4, or 5 and requires that the pumps be stopped for a short period of time. The Note permits the de-energizing of the pumps in order to perform this test and validate the assumed analysis values. If changes are made to the RCS that would cause a change to the flow characteristics of the RCS, the input values must be revalidated by conducting the test again. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> time period is adequate to perform the test, and operating experience has shown that boron stratification is not a problem during this short period with no forced flow.
Utilization of Note I is permitted provided the following conditions are met along with any other conditions imposed by initial startup test procedures:
- a.
No operations are permitted that would dilute the RCS boron concentration with coolant with boron concentrations less than required to meet SDM of LCO 3.1.1 and maintain keff < 0.99, therefore maintaining an adequate margin to criticality. Boron reduction with coolant at boron concentrations less than required to assure SDM and maintain keff < 0.99 is prohibited because a uniform concentration distribution throughout the RCS cannot be ensured when in natural circulation; and
- b.
Core outlet temperature is maintained at least 10F below saturation temperature, so that no vapor bubble may form and possibly cause a natural circulation flow obstruction.
Note 2 requires that the secondary side water temperature of each SG be
_ 500F above each of the RCS cold leg temperatures before the start of an RCP with any RCS cold leg temperature s 210 0F. This restraint is to prevent a low temperature overpressure event due to a thermal transient when an RCP is started.
An OPERABLE RCS loop comprises an OPERABLE RCP and an OPERABLE SG, which has the minimum water level specified in SR 3.4.6.2. The water level is maintained by an OPERABLE AFW train in accordance with LCO 3.7.5, "Auxiliary Feedwater System."
Similarly for the RHR System, an OPERABLE RHR loop comprises an OPERABLE RHR pump capable of providing forced flow to an OPERABLE RHR heat exchanger. RCPs and RHR pumps are OPERABLE if they are capable of being powered and are able to provide forced flow if required.
Catawba Units 1 and 2 B 3.4.6-2 Revision No. 3
RCS Loops - MODE 5, Loops Filled B 3.4.7 BASES LCO (continued) reactor coolant pump (RCP) with an RCS cold leg temperature c 210 0F.
This restriction is to prevent a low temperature overpressure event due to a thermal transient when an RCP is started.
Note 4 provides for an orderly transition from MODE 5 to MODE 4 during a planned heatup by permitting removal of RHR loops from operation when at least one RCS loop is in operation. This Note provides for the transition to MODE 4 where an RCS loop is permitted to be in operation and replaces the RCS circulation function provided by the RHR loops.
An OPERABLE RHR loop is comprised of an OPERABLE RHR pump capable of providing forced flow to an OPERABLE RHR heat exchanger.
If not in its normal RHR alignment from the RCS hot leg and returning to the RCS cold legs, the required RHR loop is OPERABLE provided the system may be placed in service from the control room, or may be placed in service in a short period of time by actions outside the control room and there are no restraints to placing the equipment in service. RHR pumps are OPERABLE if they are capable of being powered and are able to provide flow if required. An OPERABLE SG can perform as a heat sink when it has an adequate water level.
APPLICABILITY In MODE 5 with RCS loops filled, this LCO requires forced circulation of the reactor coolant to remove decay heat from the core and to provide proper boron mixing. One loop of RHR provides sufficient circulation for these purposes. However, one additional RHR loop is required to be OPERABLE, or the secondary side narrow range water level of at least two SGs is required to be 212%.
Operation in other MODES is covered by:
LCO 3.4.4, "RCS Loops-MODES 1 and 2";
LCO 3.4.5, "RCS Loops-MODE 3";
LCO 3.4.6, "RCS Loops-MODE 4";
LCO 3.4.8, "RCS Loops-MODE 5, Loops Not Filled";
LCO 3.4.17 "RCS Loops-Test Exceptions";
LCO 3.9.4, "Residual Heat Removal (RHR) and Coolant Circulation-High Water Level" (MODE 6); and LCO 3.9.5, "Residual Heat Removal (RHR) and Coolant Circulation-Low Water Level" (MODE 6).
Catawba Units 1 and 2 B 3.4.7-3 Revision No. 4
RCS Operational LEAKAGE B 3.4.13 BASES APPLICABLE SAFETY ANALYSES (continued)
The safety analysis (Ref. 3) for an event resulting in steam discharge to the atmosphere assumes that primary to secondary LEAKAGE from each steam generator (SG) is 150 gallons per day. Any event in which the reactor coolant system will continue to leak water inventory to the secondary side, and in which there will be a postulated source term associated with the accident, utilizes this leakage value as an input in the analysis. These accidents include the rod ejection accident, locked rotor accident, main steam line break, steam generator tube rupture and uncontrolled rod withdrawal accident. The rod ejection accident, locked rotor accident and uncontrolled rod withdrawal accident yield a source term due to postulated fuel failure as a result of the accident. The main steam line break and the steam generator tube rupture yield a source term due to perforations in fuel pins causing an iodine spike. Primary to secondary side leakage may escape the secondary side due to flashing or atomization of the coolant, or it may mix with the secondary side SG water inventory and be released due to steaming of the SGs. The rod ejection accident is limiting compared to the remainder of the accidents with respect to dose results. The dose results for each of the accidents delineated above are well within 10 CFR 100 limits for the rod ejection accident, and below a small fraction of 10 CFR 100 limits for the remainder of the accidents.
The RCS operational LEAKAGE satisfies Criterion 2 of 10 CFR 50.36 (Ref. 4).
LCO RCS operational LEAKAGE shall be limited to:
- a.
Pressure Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, being indicative of material deterioration. LEAKAGE of this type is unacceptable as the leak itself could cause further deterioration, resulting in higher LEAKAGE.
Violation of this LCO could result in continued degradation of the RCPB. LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.
- b.
Unidentified LEAKAGE One gallon per minute (gpm) of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the containment air monitoring and containment sump level monitoring equipment Catawba Units 1 and 2 B 3.4.13-2 Revision No. 1
RCS Operational LEAKAGE B 3.4.13 BASES LCO (continued) can detect within a reasonable time period. Violation of this LCO could result in continued degradation of the RCPB, if the LEAKAGE is from the pressure boundary.
- c.
Identified LEAKAGE Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with detection of unidentified or total LEAKAGE and is well within the capability of the RCS Makeup System. Identified LEAKAGE includes LEAKAGE captured by the pressurizer relief tank and reactor coolant drain tank, as well as quantified LEAKAGE to the containment from specifically known and located sources, but does not include pressure boundary LEAKAGE or controlled reactor coolant pump (RCP) seal leakoff (a normal function not considered LEAKAGE). Violation of this LCO could result in continued degradation of a component or system.
- d.
Primary to Secondary LEAKAGE through Any One SG The limit of 150 gallons per day per SG is based on the operational LEAKAGE performance criterion in NEI 97-06, "Steam Generator Program Guidelines" (Ref. 6). The Steam Generator Program operational LEAKAGE performance criterion in NEI 97-06 states:
"The RCS operational primary to secondary leakage through any one SG shall be limited to 150 gallons per day."
The primary to secondary LEAKAGE measurement is based on the methodology described in Ref. 5. Currently, a correction factor is applied to account for the fact that current safety analyses take the primary to secondary leak rate at reactor coolant conditions, rather than at room temperature as described in Ref. 5.
The operational LEAKAGE rate limit applies to LEAKAGE in any one SG. If it is not practical to assign the LEAKAGE to an individual SG, all the LEAKAGE should be conservatively assumed to be from one SG.
The limit in this criterion is based on operating experience gained from SG tube degradation mechanisms that result in tube LEAKAGE. The operational LEAKAGE rate criterion in conjunction with implementation of the Steam Generator Program is an effective measure for minimizing the frequency of SG tube ruptures.
Catawba Units I and 2 B 3.4.13-3 Revision No. 1
RCS Operational LEAKAGE B 3.4.13 BASES APPLICABILITY In MODES 1, 2, 3, and 4, the potential for RCPB LEAKAGE is greatest when the RCS is pressurized.
In MODES 5 and 6, LEAKAGE limits are not required because the reactor coolant pressure is far lower, resulting in lower stresses and reduced potentials for LEAKAGE.
LCO 3.4.14, "RCS Pressure Isolation Valve (PIV) Leakage," measures leakage through each individual PIV and can impact this LCO. Of the two PIVs in series in each isolated line, leakage measured through one PIV does not result in RCS LEAKAGE when the other is leak tight. If both valves leak and result In a loss of mass from the RCS, the loss must be included in the allowable unidentified LEAKAGE.
ACTIONS A.1 Unidentified LEAKAGE or identified LEAKAGE in excess of the LCO limits l must be reduced to within limits within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. This Completion Time allows time to verify leakage rates and either identify unidentified LEAKAGE or reduce LEAKAGE to within limits before the reactor must be shut down. This action is necessary to prevent further deterioration of the RCPB.
B.1 and B.2 If any pressure boundary LEAKAGE exists, or if primary to secondary LEAKAGE is not within limit, or if unidentified LEAKAGE or identified LEAKAGE cannot be reduced to within limits within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, the reactor must be brought to lower pressure conditions to reduce the severity of the LEAKAGE and its potential consequences. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.
The reactor must be brought to MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and MODE 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. This action reduces the LEAKAGE and also reduces the factors that tend to degrade the pressure boundary.
The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. In MODE 5, the pressure stresses acting on the RCPB are much lower, and further deterioration is much less likely.
Catawba Units 1 and 2 B 3.4.13-4 Revision No. 1
RCS Operational LEAKAGE B 3.4.13 BASES SURVEILLANCE SR 3.4.13.1 REQUIREMENTS Verifying RCS LEAKAGE to be within the LCO limits ensures the integrity of the RCPB is maintained. Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance. For this SR, the volumetric calculation of unidentified LEAKAGE and identified LEAKAGE is based on a density at room temperature of 77 degrees F.
The Surveillance is modified by two Notes. The RCS water inventory balance must be performed with the reactor at steady state operating conditions and near operating pressure. Therefore, Note 1 indicates that this SR is not required to be completed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of steady state operation near operating pressure have been established.
Steady state operation is required to perform a proper inventory balance; calculations during maneuvering are not useful and Note 1 requires the Surveillance to be met when steady state is established. For RCS operational LEAKAGE determination by water inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.
Note 2 states that this SR is not applicable to primary to secondary LEAKAGE because LEAKAGE of 150 gallons per day or lower cannot be measured accurately by an RCS water inventory balance.
An early warning of pressure boundary LEAKAGE or unidentified LEAKAGE is provided by the automatic systems that monitor the containment atmosphere radioactivity and the containment sump level. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. These leakage detection systems are specified in LCO 3.4.15, "RCS Leakage Detection Instrumentation."
The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Frequency is a reasonable interval to trend LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents and reduction of potential consequences. A Note under the Frequency column states that this SR is only required to be performed during steady state operation.
Catawba Units I and 2 B 3.4.13-5 Revision No. 3
RCS Operational LEAKAGE B 3.4.13 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.4.13.2 This SR verifies that primary to secondary LEAKAGE is less than or equal to 150 gallons per day through any one SG. Satisfying the primary to secondary LEAKAGE limit ensures that the operational LEAKAGE performance criterion in the Steam Generator Program is met. If this SR is not met, compliance with LCO 3.4.18, "Steam Generator (SG) Tube Integrity," should be evaluated. The 150 gallons per day limit is based on measurements taken at room temperature, with a correction factor applied to account for the fact that current safety analyses take the primary to secondary leak rate at reactor coolant conditions, rather than at room temperature.
The Surveillance is modified by a Note which states that this SR is not required to be completed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of steady state operation near operating pressure have been established. During normal operation the primary to secondary LEAKAGE is determined using continuous process radiation monitors or radiochemical grab sampling.
The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Frequency is a reasonable interval to trend primary to secondary LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents and reduction of potential consequences. A Note under the Frequency column states that this SR is only required to be performed during steady state operation.
REFERENCES
- 1.
10 CFR 50, Appendix A, GDC 30.
- 2.
Regulatory Guide 1.45, May 1973.
- 3.
UFSAR, Section 15.
- 4.
10 CFR 50.36, Technical Specifications, (cX2Xii).
- 5.
EPRI TR-1 04788-R2, "PWR Primary-to-Secondary Leak Guidelines," Revision 2.
- 6.
NEI 97-06, 'Steam Generator Program Guidelines."
Catawba Units 1 and 2 B 3.4.13-6 Revision No. 2
SG Tube Integrity B 3.4.18 B 3.4 REACTOR COOLANT SYSTEM (RCS)
B 3.4.18 Steam Generator (SG) Tube Integrity BASES BACKGROUND SG tubes are small diameter, thin walled tubes that carry primary coolant through the primary to secondary heat exchangers. The SG tubes have a number of important safety functions. SG tubes are an integral part of the reactor coolant pressure boundary (RCPB) and, as such, are relied upon to maintain the primary system's pressure and inventory. The SG tubes isolate the radioactive fission products in the primary coolant from the secondary system. In addition, as part of the RCPB, the SG tubes are unique in that they act as the heat transfer surface between the primary and secondary systems to remove heat from the primary system. This Specification addresses only the RCPB integrity function of the SG. The SG heat removal function is addressed by LCO 3.4.4, "RCS Loops - MODES I and 2," LCO 3.4.5, "RCS Loops - MODE 3," LCO 3.4.6, "RCS Loops - MODE 4," and LCO 3.4.7, "RCS Loops - MODE 5, Loops Filled."
SG tube integrity means that the tubes are capable of performing their intended safety functions consistent with their licensing basis, including applicable regulatory requirements.
SG tubing is subject to a variety of degradation mechanisms. SG tubes may experience degradation related to corrosion phenomena, such as wastage, pitting, intergranular attack, and stress corrosion cracking, along with other mechanically induced phenomena such as denting and wear. These degradation mechanisms can impair tube integrity if they are not managed effectively. The SG performance criteria are used to manage SG tube degradation.
Specification 5.5.9, "Steam Generator (SG) Program," requires that a program be established and implemented to ensure that SG tube integrity is maintained. Pursuant to Specification 5.5.9, tube integrity is maintained when the SG performance criteria are met.
There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE. The SG performance criteria are described in Specification 5.5.9. Meeting the SG performance criteria provides reasonable assurance of maintaining tube integrity at normal and accident conditions.
Catawba Units 1 and 2 B, 3.4.18-1 Revision No. 0
SG Tube Integrity B 3.4.18 BASES BACKGROUND (continued)
The processes used to meet the SG performance criteria are defined by the Steam Generator Program Guidelines (Ref. 1).
APPLICABLE SAFETY ANALYSES The design basis accidents for which the primary to secondary LEAKAGE is a pathway for release of activity to the environment include the main steam line break, SG tube rupture, reactor coolant pump locked rotor accident, single rod withdrawal accident, and rod ejection accident. The analysis of radiological consequences of these design basis accidents, except for a SG tube rupture, assumes that the total primary to secondary LEAKAGE from each SG initially is 150 gallons per day. Transient thermal hydraulic analyses of these design basis accidents determine the primary to secondary LEAKAGE changes (decreases or increases) that result from changing pressures and temperatures. These calculated values are used in the analyses of radiological consequences of these design basis accidents.
The source term in the primary coolant for some design basis accidents (e.g., reactor coolant pump locked rotor accident and rod ejection accident) is associated primarily with fuel rods calculated to be breached. For other design basis accidents (e.g.,
main steam line break and SG tube rupture), the source term in the primary coolant consists primarily of the levels of DOSE EQUIVALENT 1-131 radioactivity levels calculated for the design basis accident. This, in turn, is based on the limiting values in the Technical Specifications and postulated iodine spikes.
For accidents in which the source term in the primary coolant consists of the DOSE EQUIVALENT 1-131 activity levels, the SG tube rupture yields the limiting values for radiation doses at offsite locations. In the calculation of radiation doses following this event, the rate of primary to secondary LEAKAGE in the intact SGs is set equal to the operational LEAKAGE rate limits in LCO 3.4.13, "RCS Operational LEAKAGE." For the ruptured SG, a double ended rupture of a single tube is assumed. Following the initiating event, contaminants in flashed and atomized break flow (the latter computed for time spans during which the tubes are calculated to be uncovered), as well as secondary coolant, may be released to the atmosphere. Before reactor trip, the accident analysis for the SG tube rupture assumes that these contaminants are released to the condenser and from there to the environment with credit taken for scrubbing of iodine contaminants in the condenser. Following reactor trip (and loss of offsite power), the accident analysis assumes that these contaminants are released to the environment through the SG power operated relief valves Catawba Units I and 2 B 3.4.18-2 Revision No. 0
SG Tube Integrity B 3.4.18 BASES APPLICABLE SAFETY ANALYSES (continued) and the main steam code safety valves until such time as the closure of these valves can be credited.
For other design basis accidents such as main steam line break, rod ejection accident, reactor coolant pump locked rotor accident, and uncontrolled rod withdrawal accident, the tubes are assumed to retain their structural integrity (i.e., they are assumed not to rupture). The LEAKAGE is assumed to be initially at the limit given in LCO 3.4.13.
The three SG performance criteria and the limits included in LCO 3.4.16, "RCS Specific Activity," for DOSE EQUIVALENT 1-131 in primary coolant, and in LCO 3.7.17, "Secondary Specific Activity,"
for DOSE EQUIVALENT 1-131 in secondary coolant, ensure the plant is operated within its analyzed condition. The dose consequences resulting from the most limiting design basis accident are within the limits defined in GDC 19 (Ref. 2), 10 CFR 100 (Ref. 3), or the NRC approved licensing basis (e.g., a small fraction of these limits or 10 CFR 50.67 (Ref. 4)).
SG Tube Integrity satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).
LCO The LCO requires that SG tube integrity be maintained. The LCO also requires that all SG tubes that satisfy the repair criteria be plugged in accordance with the Steam Generator Program.
During a SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is removed from service by plugging. If a tube was determined to satisfy the repair criteria but was not plugged, the tube may still have tube integrity.
In the context of this Specification, a SG tube is defined as the entire length of the tube, including the tube wall and any repairs made to it, between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet. The tube-to-tubesheet weld is not considered part of the tube.
A SG tube has tube integrity when it satisfies the SG performance criteria. The SG performance criteria are defined in Specification 5.5.9, "Steam Generator (SG) Program," and describe acceptable SG tube performance. The Steam Generator Program also provides the evaluation process for determining conformance with the SG performance criteria.
Catawba Units 1 and 2 B 3.4.18-3 Revision No. 0
SG Tube Integrity B 3.4.18 BASES LCO (continued)
There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE. Failure to meet any one of these criteria is considered failure to meet the LCO.
The structural integrity performance criterion provides a margin of safety against tube burst under normal and accident conditions, and ensures structural integrity of the SG tubes under all anticipated transients included in the design specification.
Structural integrity requires that the primary membrane stress intensity in a tube not exceed the yield strength for all ASME Code, Section 1I1, Service Level A (normal operating conditions) and Service Level B (upset or abnormal conditions) transients included in the design specification. This includes safety factors and applicable design basis loads based on ASME Code, Section l1l, Subsection NB (Ref. 5) and Draft Regulatory Guide 1.121 (Ref.
6). Tube burst is defined as, "The gross structural failure of the tube wall. The condition typically corresponds to an unstable opening displacement (e.g., opening area increased in response to constant pressure) accompanied by ductile (plastic) tearing of the tube material at the ends of the degradation." Tube collapse is defined as, "For the load displacement curve for a given structure, collapse occurs at the top of the load versus displacement curve where the slope of the curve becomes zero." Significant is defined as, "An accident loading condition other than differential pressure is considered significant when the addition of such loads in the assessment of structural integrity performance criterion causes a lower structural limit or limiting burst/collapse condition to be established."
The accident induced leakage performance criterion ensures that the primary to secondary LEAKAGE caused by a design basis accident, other than a SG tube rupture, is within the accident analysis assumptions. The accident analysis assumes that accident induced leakage does not exceed 150 gallons per day through each SG for a total of 600 gallons per day through all SGs. The accident induced leakage rate includes any primary to secondary LEAKAGE existing prior to the accident in addition to primary to secondary LEAKAGE induced during the accident.
The operational LEAKAGE performance criterion provides,an observable indication of SG tube conditions during plant operation. The limit on operational LEAKAGE is contained in LCO 3.4.13, "RCS Operational LEAKAGE," and limits primary to secondary LEAKAGE through any one SG to 150 gallons per day.
This limit is based on the assumption that a single crack leaking Catawba Units 1 and 2 B 3.4.18-4 Revision No. 0
SG Tube Integrity B 3.4.18 BASES LCO (continued) this amount would not propagate to a SG tube rupture under the stress conditions of a loss of coolant accident or a main steam line break. If this amount of LEAKAGE is due to more than one crack, the cracks are very small, and the above assumption is conservative.
APPLICABILITY SG tube integrity is challenged when the pressure differential across the tubes is large. Large differential pressures across SG tubes can only be experienced in MODES 1, 2, 3, and 4.
RCS conditions are far less challenging in MODES 5 and 6 than during MODES 1, 2, 3, and 4. In MODES 5 and 6, primary to secondary differential pressure is low, resulting in lower stresses and reduced potential for LEAKAGE.
ACTIONS The ACTIONS are modified by a Note clarifying that the Conditions may be entered independently for each SG tube. This is acceptable because the Required Actions provide appropriate compensatory actions for each affected SG tube. Complying with the Required Actions may allow for continued operation, and subsequent affected SG tubes are governed by subsequent Condition entry and application of associated Required Actions.
A.1 and A.2 Condition A applies if it is discovered that one or more SG tubes examined in an inservice inspection satisfy the tube repair criteria but were not plugged in accordance with the Steam Generator Program as required by SR 3.4.18.2. An evaluation of SG tube integrity of the affected tube(s) must be made. SG tube integrity is based on meeting the SG performance criteria described in the Steam Generator Program. The SG repair criteria define limits on SG tube degradation that allow for flaw growth between inspections while still providing assurance that the SG performance criteria will continue to be met. In order to determine if a SG tube that should have been plugged has tube integrity, an evaluation must be completed that demonstrates that the SG performance criteria will continue to be met until the next SG tube inspection. The tube integrity determination is based on the estimated condition of the tube at the time the situation is discovered and the estimated growth of the degradation prior to the next SG tube inspection. If it is determined that tube integrity is not being maintained, Condition B applies.
Catawba Units 1 and 2 B 3.4.18-5 Revision No. 0
SG Tube Integrity B 3.4.18 BASES ACTIONS (continued)
A Completion Time of 7 days is sufficient to complete the evaluation while minimizing the risk of plant operation with a SG tube that may not have tube integrity.
If the evaluation determines that the affected tube(s) have tube integrity, Required Action A.2 allows plant operation to continue until the next outage provided the inspection interval continues to be supported by an operational assessment that reflects the affected tubes. However, the affected tube(s) must be plugged prior to entering MODE 4 following the next refueling outage or SG tube inspection. This Completion Time is acceptable since operation until the next inspection is supported by the operational assessment.
B.1 and B.2 If the Required Actions and associated Completion Times of Condition A are not met or if SG tube integrity is not being maintained, the reactor must be brought to MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and MODE 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.
The allowed Completion Times are reasonable, based on operating experience, to reach the desired plant conditions from full power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE SR 3.4.18.1 REQUIREMENTS During shutdown periods the SGs are inspected as required by this SR and the Steam Generator Program. NEI 97-06, Steam Generator Program Guidelines (Ref. 1), and its referenced EPRI Guidelines, establish the content of the Steam Generator Program. Use of the Steam Generator Program ensures that the inspection is appropriate and consistent with accepted industry practices.
During SG inspections a condition monitoring assessment of the SG tubes is performed. The condition monitoring assessment determines the "as found" condition of the SG tubes. The purpose of the condition monitoring assessment is to ensure that the SG performance criteria have been met for the previous operating period.
Catawba Units 1 and 2 B 3.4.18-6 Revision No. 0
SG Tube Integrity B 3.4.18 BASES SURVEILLANCE REQUIREMENTS (continued)
The Steam Generator Program determines the scope of the inspection and the methods used to determine whether the tubes contain flaws satisfying the tube repair criteria. Inspection scope (i.e., which tubes or areas of tubing within the SG are to be inspected) is a function of existing and potential degradation locations. The Steam Generator Program also specifies the inspection methods to be used to find potential degradation.
Inspection methods are a function of degradation morphology, non-destructive examination (NDE) technique capabilities, and inspection locations.
The Steam Generator Program defines the Frequency of SR 3.4.18.1. The Frequency is determined in part by the operational assessment and other limits in the Steam Generator Examination Guidelines (Ref. 7). The Steam Generator Program uses information on existing degradations and growth rates to determine an inspection Frequency that provides reasonable assurance that the tubing will meet the SG performance criteria at the next scheduled inspection. In addition, Specification 5.5.9 contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.
SR 3.4.18.2 During a SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is removed from service by plugging. The tube repair criteria delineated in Specification 5.5.9 are intended to ensure that tubes accepted for continued service satisfy the SG performance criteria with allowance for error in the flaw size measurement and for future flaw growth. In addition, the tube repair criteria, in conjunction with other elements of the Steam Generator Program, ensure that the SG performance criteria will continue to be met until the next inspection of the subject tube(s). Ref. I and Ref. 7 provide guidance for performing operational assessments to verify that the tubes remaining in service will continue to meet the SG performance criteria.
The Frequency of prior to entering MODE 4 following a SG tube inspection ensures that the Surveillance has been completed and all tubes satisfying the repair criteria are plugged prior to subjecting the SG tubes to significant primary to secondary pressure differential.
Catawba Units 1 and 2
.B 3.4.18-7 Revision No. 0
SG Tube Integrity B 3.4.18 BASES REFERENCES
- 1.
NEI 97-06, "Steam Generator Program Guidelines."
- 3. 10 CFR 100.
- 4. 10 CFR 50.67.
- 5. ASME Boiler and Pressure Vessel Code,Section III, Subsection NB.
- 6. Draft Regulatory Guide 1.121, "Basis for Plugging Degraded Steam Generator Tubes," August 1976.
- 7. EPRI TR-107569, "Pressurized Water Reactor Steam Generator Examination Guidelines."
Catawba Units I and 2
-I B 3.4.18-8 Revision No. 0